The Shunbei oil formation is a deep, high-temperature carbonate reservoir. Acid fracturing is an effective technology to stimulate this formation. For acid fracturing, the temperature field is fundamental information for the acid system selection, acid–rock reaction, live acid penetration distance prediction, acid fracturing design, etc. Therefore, in this paper, we conduct a numerical study on the temperature field in acid fracturing to account for the acid–rock reaction in the Shunbei formation. Firstly, a new mathematical model of the fracture temperature field during acid fracturing is established based on the laws of mass and energy conservation and acid–rock reaction kinetics. The fracture model is based on a PKN model, which accounts for a few factors, such as the acid–rock reaction heat, acid–rock reaction rate dependence on the temperature, and the fracture width change with acid erosion. Then, the numerical mode is developed. Next, an extensive numerical study and a parameter analysis are conducted based on the model with the field data from the Shunbei formation. The study shows that the acid–rock reaction in acid fracturing has obvious effects on the temperature field, resulting in a 10~20 °C increase in the Shunbei formation. The acid–rock reaction dependence on temperature is a factor to be accounted for. The rock dissolution increases first and then decreases from the inlet to the tip of the fracture, unlike the monotonous decrease without temperature dependence. The temperature gradient is high near the inlet and then decreases gradually. Beyond half of the fracture, the temperature is close to the formation temperature. The temperature drops fast in the initial injection stage and tends to stabilize at about 50 min.

Shale reservoirs contain a certain amount of clay minerals, which can hydrate through imbibition when in contact with various water-based fluids during drilling and completion. Shale hydration can lead to structural changes in the shale such as the expansion of bedding planes and propagation of microfractures, consequently affecting the initiation and propagation of hydraulic fractures. However, the effect of shale hydration under confining pressure on hydraulic fracture propagation and stimulation effect is still unclear. To this end, a novel experimental method integrating shale hydration and hydraulic fracturing was proposed based on the laboratory triaxial hydraulic fracturing simulation system. This method enables a more realistic simulation of shale hydration and hydraulic fracturing process happening in downhole conditions. The experimental results show that under simulated reservoir conditions, water imbibition increases over time with the imbibition rate reaching its peak within 24 h. The breakdown pressure, number of fractures, and complexity of fractures are positively correlated with imbibition time. The increase in fracture complexity could be attributed to the increase in the number of fractures. In contrast, imbibition pressure (injection pressure for imbibition) has little influence on water imbibition. For specimens under different imbibition pressure, the breakdown pressure and the number of fractures are close, and the complexity of fractures does not change prominently; all are T-shaped fractures. It is believed that the closure of microfractures under confining pressure caused by hydration is the main reason for the increase in breakdown pressure. Higher breakdown pressure means higher net pressure in the wellbore, which facilitates fracture initiation where the breakdown pressure is higher. Therefore, shale hydration is conducive to the initiation of multiple fractures, thus increasing the number and complexity of fractures.

To investigate the impact of CO₂ on rocks during the whole period of CO₂ pre-pad energized fracturing operation for thin interbedded shale reservoir, including fracturing and well shut-in, a series of laboratory triaxial fracturing experiments and CO₂ soaking experiments were conducted on thin interbedded shale (from Jimsar formations). In these experiments, combined with computed tomography (CT), the effect of fracturing fluid, horizontal principal stress difference, vertical principal stress, and natural fractures on fracture morphology were studied respectively. And based on X-ray diffraction (XRD) and scanning electron microscopy (SEM) experiments, the dissolution of minerals and the changes of pore structure before and after CO₂ soaking were analyzed. The results of the fracturing experiment show that the bedding planes are easy to be opened by low viscosity of CO₂ and the longitudinal fractures intersect with bedding planes to build a complex fracture network. During CO₂ fracturing of thin interbedded shale, the horizontal principal stress difference is no longer a crucial factor to form a complex fracture network, but the vertical stress and natural fractures play important roles. And the soaking experiments indicate that the main dissolved mineral is carbonate whose dissolution ratio can reach 45.2% after soaking for 5 days, leading to the expansion of original pores or the exposure of new pores.

Fracture-driven interactions (FDIs) in unconventional reservoirs significantly affect well production and have thus garnered extensive attention from the scientific community. Furthermore, since the industry transitioned to using large completion designs with closer well spacing and infill drilling, FDIs have occurred more frequently and featured more prominently, which has primarily led to destructive interference. When infill wells (i.e., “child” wells) are fractured, older, adjacent producing wells (i.e., “parent” wells) are put directly at risk of premature changes in production behavior. Some wells may never fully recover following exposure to severe FDIs and, in the worst case scenario, will permanently stop producing. To date, previous investigations into FDIs have focused mainly on diagnosis and detection. As such, their formation mechanism is not well understood. To address this deficiency, a three-dimensional, multi-fracture propagation simulator was constructed based on the unconventional fracture model (UFM) and applied to a system that included both an older, adjacent passive well (“parent” well) and an active well (“child” well). Herein, the theoretical framework for overall complex fracture modeling is described. Furthermore, numerical simulation results are presented, demonstrating the critical roles of in-situ stress distribution and pre-existing natural fractures and aiding in the development of appropriate strategies for managing FDIs.